Source array for use in marine seismic exploration

ABSTRACT

A staggered vertical marine seismic source contains upper and lower arrays ( 10, 11 ) of emitters of seismic energy (S11, S12; S21, S22). The upper array ( 10 ) is horizontally displaced relative to the lower array ( 11 ). The source is used in a marine seismic surveying arrangement that has means for moving the source and at least one seismic receiver. 
     In use, the source is moved through the water in a direction parallel to the direction in which the two arrays are displaced. The arrays ( 10, 11 ) are fired sequentially, and the time delay between the firing of the first-fired array and firing of the second-fired array is chosen such that each seismic emitter in one array is fired at the same x- and y-co-ordinates as the corresponding emitter in the other array. The seismic wavefields generated by firing the two arrays are thus generated at the same x- and y-co-ordinates, but at different depths. 
     The seismic data recorded at the receiver(s) as a consequence of firing the first array can be used to de-ghost the seismic data acquired as a result of firing the second array or vice-versa, thereby eliminating or reducing the effect of source-side ghost reflections and reverberations.

This application claims the benefit of Provisional Application No.60/174,301, filed Apr. 3, 2000.

The present invention relates to a seismic source, in particular to asource for use in marine seismic surveying. The present invention alsorelates to a marine seismic surveying arrangement including a source, toa method of operating the source and to a method of de-ghosting marineseismic data.

The principle of marine seismic surveying is shown schematically in FIG.1. Seismic energy emitted in a generally downwards direction from asource of seismic energy 1 is reflected by the sea bed 2 and by theearth strata or geological structures beneath the sea bed, and isreceived by an array of seismic receivers 3 such as hydrophones.Analysis of the energy received at the receiving array 3 can provideinformation about the earth strata or geological structures beneath theseabed. In the marine seismic surveying arrangement shown in FIG. 1, thesource of seismic energy 1 is suspended from a survey vessel 4 and thearray of seismic receivers 3 is towed by the survey vessel 3.

One problem associated with conventional marine seismic surveying isthat of “ghost reflections”. Ghost reflections occur when upwardlytravelling seismic energy is reflected or scattered downwards at the seasurface. A related problem in marine seismic surveying is that of“reverberations”. Reverberations occur when seismic energy is reflectedbetween the sea surface and the sea-bed. The problems of ghostreflections and reverberations are explained in FIGS. 2(a) to 2(d).

FIG. 2(a) shows a “primary reflection”. Seismic energy is emitteddownwards by the source 1, is reflected by a geological feature belowthe sea bed, and the reflected signal is detected at the receiver 3. Ananalysis of the seismic signal generated by the primary reflectionprovides information about the geological feature responsible forreflecting the seismic energy. (In practice, refraction may occur at thesea-bed, but this has been omitted from FIGS. 2(a) to 2(d) for clarity.)

FIG. 2(b) shows a ghost reflection. Seismic energy that has been emittedupwards by the source is reflected or scattered downwards by the seasurface. The seismic energy that is reflected or scattered downwards maythen be incident on the target geological feature, undergo reflection,and be reflected to the receiver. Seismic energy that follows the pathshown in FIG. 2(b) will have a different travel time from the source tothe receiver than will energy that follows the primary path of FIG.2(a). Ghost reflections are an undesirable source of contamination ofseismic data since they tend to obscure the interpretation of dataproduced by the primary reflection.

FIGS. 2(c) and 2(d) show reverberations, in which seismic energyundergoes reflections between the sea-bed and the sea-surface.Reverberations can occur in the case of seismic energy emitted in anup-going direction by the source (FIG. 2(c)) and also in the case ofseismic energy emitted in a down-going direction by the source (FIG.2(d)). As is the case for ghost reflections, reverberations are anundesirable source of contamination of seismic data, since they obscurethe interpretation of the primary reflection from the earth's interior.

FIGS. 2(b), 2(c) and 2(d) show source-side ghost reflections andreverberations—that is, ghost reflections and reverberations that occurbefore the seismic energy is reflected by the target geologicalstructure. (Indeed it will be noted that the path of seismic energyshown in FIG. 2(d) does not involve a reflection by the targetgeological structure.) Ghost reflections and reverberations can alsooccur after the seismic energy has been reflected from the targetgeological structure, and these are known as receiver-side ghostreflections or reverberations.

A number of schemes for minimising the effect of ghost reflections andreverberations on seismic data have been proposed. For most surveyarrangements, the attenuation of ghost reflections and reverberations isequivalent to separating the up-going and down-going seismic wavefields.

F. J. Barr and J. J. Saunders have proposed, in a paper presented at the59th SEG Meeting (1989), a method of attenuating ghost reflections andreverberations by recording the reflected seismic signal using twodifferent types of seismic receivers, namely using both hydrophones andgeophones. The up-going wave field is recorded by the hydrophone and thegeophone with the same polarity, while the down-going wave field isrecorded by the hydrophone and the geophone with opposite polarities.The difference between the signal recorded by the hydrophone and thesignal recorded by the geophone allows the up-going wavefield to beseparated from the down-going wavefield.

An alternative method for attenuating ghost reflections andreverberations is to use two receivers located at different depths. Thismethod is based on the principle that waves travelling in differentdirections will have spatial derivatives of different signs, so thatcomparing the signal obtained at one receiver with the signal obtainedby the other receiver will allow the up-going wavefield to be separatedfrom the down-going wavefield.

These prior art methods separate the up-going and down-going wave fieldsat the receiver location. That is, they attempt to remove the ghostreflections and reverberations that arise after the seismic energy hasbeen reflected by the target geological structure. This is known asreceiver-side deghosting. These prior art methods do not, however,address the problem of the ghost reflections and reverberations thatoccur before the seismic energy is reflected by the target geologicalstructure.

A first aspect of the present invention provides a marine seismic sourcecomprising: a first array of N emitters of seismic energy, where N is aninteger greater than 1; and a second array of N emitters of seismicenergy; wherein, in use, the first array is disposed at a first depthand the second array is disposed at a second depth greater than thefirst depth, and the j^(th) emitter of the first array (j=1, 2 . . . N)is displaced by a non-zero horizontal distance d_(H) from the j^(th)emitter of the second array along a first direction; and the jth emitterof the first array and the jth emitter of the second array both lie in avertical plane parallel to the first direction.

The use of two arrays of emitters of seismic energy at different depthsallows the up-going and down-going seismic wavefields to be separatedfrom one another, as will be described below. The effect of source-sideghost reflections and reverberations on the seismic data can be reducedor eliminated.

A second aspect of the present invention provides a marine seismicsurveying arrangement comprising a marine seismic receiver; and aseismic source as defined above; means for moving the seismic source;and one or more seismic receivers.

A third aspect of the present invention provides a method of operating amarine seismic source as defined above, the method comprising the stepsof: moving the seismic source at a speed v along the first direction;firing one of the first and second arrays of emitters of seismic energy;and firing the other of the first and second arrays of emitters ofseismic energy after a time d_(H)/v. The time delay of d_(H)/v betweenthe firings of the two arrays of seismic sources ensures that eachemitter of one array is fired at the same point in the x- andy-directions as the corresponding emitter of the other array, but atdifferent depths. This allows the seismic data generated by one of thearrays to be used to de-ghost the seismic data generated by the other ofthe arrays.

A fourth aspect of the present invention provides a method of processingmarine seismic data comprising the steps of: firing a first emitter ofseismic energy at a point in a fluid medium having components (x₁, y₁,z₁), and detecting the resultant first seismic data at a receiver array;firing a second emitter of seismic energy at a point in the fluid mediumhaving components (x₁, y₁, z₂), where z₁≠z₂, and detecting the resultantsecond seismic data at the receiver array; and using the second seismicdata to reduce the effects of source-side reflections and/or scatteringat the sea surface on the first seismic data.

Preferred features of the invention are set out in the dependent claims.

Preferred embodiments of the present invention will now be described byway of illustrative examples with reference to the accompanying figures,in which:

FIG. 1 is a schematic view of a typical marine seismic surveyingarrangement;

FIGS. 2(a) to 2(d) are schematic illustrations of the problems of ghostreflections and reverberations;

FIG. 3 is a schematic view of a vertical source array illustrating theprinciples of the de-ghosting method of the present invention;

FIG. 4 is a schematic illustration of a vertical source array accordingto an embodiment of the present invention;

FIG. 5 shows a typical seismic signal recorded by a receiver in a marineseismic surveying arrangement that contains a seismic source accordingto an embodiment of the present invention;

FIG. 6 shows the signal of FIG. 5 after processing to attenuatesource-side ghost reflections and reverberations;

FIG. 7 illustrates the average amplitude spectrum of the signal of FIG.5; and

FIG. 8 illustrates the average amplitude of the signal of FIG. 6.

FIG. 3 illustrates the general principle of the de-ghosting method ofthe present invention. FIG. 3 shows a vertical source array thatconsists of two emitters of seismic energy S1 and S2 that have identicalemission characteristics to one another. The emitters are disposed inthe water at two different depths. The upper emitter S1 is disposedsubstantially vertically above the lower emitter S2.

The source array generates a seismic wavefield that has both up-goingand down-going components. The wavefield travelling upwards generatessource-side ghost reflections and up-going reverberations in the waterlayer. The wavefield travelling downwards from the source arraygenerates the primary reflection and also generates down-goingreverberations.

Consider a hypothetical emitter of seismic energy S having identicalemission characteristics to the emitters S1 and S2, placed at themid-point between the upper emitter S1 and the lower emitter S2. Thisemitter S would generate up-going and down-going source wavefields at areference time t. The total wavefield S(t) emitted by the hypotheticalemitter S is the sum of the up-going and down-going source wavefields,that is:S(t)=u(t)+d(t)  (1)

In this equation, u(t) is the up-going source wavefield and d(t) is thedown-going source wavefield emitted by the hypothetical emitter S.

The emitters S1 and S2 generate up-going and down-going wavefields.These wavefields can be described, relative to time t, by the followingequations:S ₁(t)=u(t−dt)+d(t+dt)  (2)S ₂(t)=u(t+dt)+d(t−dt)  (3)

In these equations, S₁ is the wavefield emitted by the upper emitter S1and S₂ is the wavefield emitted by the lower emitter S2. The time dt isthe time that seismic energy would take to travel from the upper orlower emitter S1 or S2 to the position of the hypothetical emitter S.Since the hypothetical emitter S is at the mid-point between the upperemitter S1 and the lower emitter S2, the time dt is equal to half thetime taken for seismic energy to travel between the upper emitter S₁ andthe lower emitter S₂ or vice versa.

On the assumption that dt is small, the terms in equations (2) and (3)can be expanded using a first-order Taylor expansion, as follows:S ₁(t)=u(t)−u′(t)dt+d(t)+d′(t)dt  (4)S ₂(t)=u(t)+u′(t)dt+d(t)−d′(t)dt  (5)

In equations (4) and (5), u′(t) and d′(t) are the time derivatives ofu(t) and d(t)1, respectively.

The sum of the two source wavefields S₁ and S₂ and the differencebetween the two source wavefields S₁ and S₂ can be derived fromequations (4) and (5) as follows:Sum=S ₁(t)+S ₂(t)=2u(t)+2d(t)  (6)Dif=S ₂(t)−S ₁(t)=2u′(t)dt−2d′(t)dt  (7)

Integrating both sides of equation (7) with respect to time leads to thefollowing result:Intdif=2u(t)dt−2d(t)dt  (8)

Equations (6) and (8) may now be combined, to eliminate u(t). This leadsto the following expression for the down-going source wavefield d(t):d(t)=(Sum−Intdif/dt)/4  (9)

Thus, by using a vertical source array that consists of two emitters ofseismic energy that have identical emission characteristics, with oneemitter disposed above the other, it is possible to derive thedown-going source wavefield d(t) using equation (9) above. This allowsthe effect of the up-going wavefield u(t) to be eliminated when seismicdata acquired using the source is processed.

The principle of reciprocity is a fundamental principle of wavepropagation, and states that a signal is unaffected by interchanging thelocation and character of the sources and receivers. For example, if asurveying arrangement with an array of seismic sources at point A and areceiver at point B gives a certain signal at the receiver, then using areceiver array at point A and a single source at point B would lead tothe same signal, provided that the source array corresponds to thereceiver array. (By “corresponds”) it is meant that the source arraycontains the same number of sources as the receiver array has receivers,and that the sources in the source array are arranged in the samelocations relative to one another as the receivers in the receiverarray.)

One consequence of the principle of reciprocity is that the theorydescribed above with relation to equations (1) to (9) above could beused for wave field separation using two vertically separated receivers.This would provide a method of receiver-side de-ghosting, which wouldenable the up-going wave field at the receiver, which contains theprimary reflection, to be separated from the down-going wavefield causedby reflection or scattering at the sea surface.

The above discussion relates to a vertical source array that containsjust two emitters, with one emitter being disposed above the other.However, the same principle can be applied to a source that comprises afirst array of two or more emitters of seismic energy disposed above asecond array of two or more emitters of seismic energy. It is, however,necessary for the first and second arrays of emitters to havesubstantially identical emission characteristics to one another—that is,each emitter array must contain the same number of emitters, and eachemitter in one array must have identical emission characteristics to thecorresponding emitter in the other array. Furthermore, the relativearrangement and separation of the emitters in one array must be the sameas the relative arrangement and separation of the emitters in the otherarray.

If the upper and lower emitters S1 and S2 were fired simultaneously, areceiver would record the combination of the wavefield generated by theupper emitter S1 and the wavefield generated by the lower emitter S2. Itwould therefore not be possible to apply the de-ghosting method outlinedabove, since the difference between the two wavefields would not beknown. To apply the method using the seismic source shown in FIG. 3, itwould be necessary to maintain the source stationary in the water, andfire the two emitters one after the other. This would generate twodistinct wavefields S₁, S₂ that could be recorded separately andprocessed according to equations (1) to (9). However, it would beinconvenient in practice to have to hold the source stationary in thewater.

In principle, the two separate wavefields required for the de-ghostingmethod could also be obtained by using firing a single emitter at onedepth, altering the depth of the emitter, and firing the emitter again.However, this method would also be inconvenient to carry out.

In a preferred embodiment of the present invention, therefore, astaggered vertical source is used consisting of two emitters or of twoemitter arrays, with, in use, one emitter or emitter array beingdisposed at one depth and the other being disposed at a different depth.The two emitters, or two emitter arrays, are displaced horizontally withrespect to one another. In use, the source is moved through the water inthe direction along which the emitters, or emitter arrays, aredisplaced. There is a time delay between the firing of one of theemitters or emitter arrays and the firing of the other emitter oremitter array. The time delay between the firings and the speed ofmovement of the source are chosen such that, in the case of a sourcehaving just two emitters, the point at which the upper emitter is firedhas the same x- and y-co-ordinates as the point at which the loweremitter is fired. In the case of a source having two arrays of emitters,the time delay between firing one array and firing the other array ischosen so that the point at which an emitter in one array is fired hasthe same x- and y-co-ordinates as the point at which the correspondingemitter in the other array is fired, for all emitters in the array.Thus, the invention makes it straightforward to generate identicalseismic wavefields at different depths but at the same x- andy-co-ordinates. The seismic data generated by one wavefield can then beused to de-ghost the seismic data generated by the other wavefield,using equation (9) above.

FIG. 4 shows an embodiment of the invention in which the source includestwo arrays 10, 11 each having two emitters of seismic energy S11, S12;S21, S22. The four emitters S11, S12; S21, S22 have substantiallyidentical emission characteristics to one another. The separationbetween the two emitters S11, S12 of the first array 10 is substantiallyequal to the separation between the two emitters S21, S22 of the secondarray. In this embodiment, one array 10 is disposed at a depth of fourmetres, whereas the other array 11 is disposed at a depth of 10 metres.The axis of each emitter array is preferably horizontal, so that eachemitter S11, S12 of the first array 10 is at a depth of 4 metres andeach emitter S21, S22 of the second array 11 is at a depth of 10 m. Thesource is intended to be moved through the water at a speed v, and thisis most conveniently done by towing the source from a survey vessel, asshown in FIG. 1.

In addition to being separated in the vertical direction (z-direction),the two arrays are also displaced in a horizontal direction. Thedirection of displacement of the two arrays is the direction in whichthe source is towed in use. The arrays are displaced by a horizontaldistance d_(H). In FIG. 4, the direction in which the arrays aredisplaced, and in which the source is moved in use, is chosen to be thex-direction for convenience of description.

The two arrays are not displaced in the direction perpendicular to thedirection of movement of the source (in FIG. 4 this is the y-directionand extends out of the plane of the paper). An emitter of one array andthe corresponding emitter of the other array are both disposed in acommon vertical plane, that is parallel to the direction of movement ofthe source.

The difference in depth between the first and second emitter arraysshould be chosen such that 1/dt<f_(max), where f_(max) is the maximumfrequency in the seismic data. The time dt is determined by the depthdifference between the two emitter arrays and by the velocity of seismicenergy in water, which is a known quantity. The embodiment of FIG. 4 isintended for use with a maximum frequency f_(max)≦90 Hz, and a depthdifference of 6 m has been found to be acceptable in this case.

As noted above, the two emitter arrays of the source shown in FIG. 4have a horizontal displacement, d_(H). The horizontal displacement ismeasured between an emitter of the array nearer the towing vessel andthe corresponding emitter of the array further from the towing vessel.

The marine seismic source shown in FIG. 4 can be used in a marineseismic surveying arrangement. In addition to the source, thearrangement would also comprise one or more seismic receivers, andmeans, such as a towing vessel, for moving the source through the water.The marine seismic surveying arrangement would also comprises controlmeans for firing the emitters, and recording means for recording seismicdata acquired by the receiver(s).

In a particularly preferred embodiment, the horizontal displacementbetween the two emitter arrays is substantially equal to the shot pointinterval of the marine seismic surveying arrangement. Thus, for aseismic surveying arrangement that generates a shot point interval of,for example, 25 m, the horizontal displacement of the emitter arrays ofthe seismic source is preferably approximately 25 m.

In this embodiment, the emitter arrays are fired in a “flip-flop”sequence at equal intervals of, in this example, 25 m. That is to say,the emitters on the array nearer the towing vessel are fired initiallyand they may be fired consecutively, or simultaneously. After a timedelay that is equal to the time required for the towing vessel to travel25 m, the emitters of the array further from the boat are fired. Thisresults in two shot records generated at points having the samex-co-ordinate and the same y-co-ordinate, but at different depths.

In FIG. 4 the array at the shallower depth is shown as the array nearerthe towing vessel. The invention is not limited to this, however, andthe array at the shallower depth could be the array further from thetowing vessel.

The signals generated at the receiver or receiver array as the result offiring the first emitter array and subsequently firing the secondemitter array are recorded in any conventional manner. Since, asexplained above, the signals were emitted by the two emitter arrays atthe same x- and y-co-ordinates but at different z-co-ordinates, theresults can be analysed using the theory outlined above with regard toequations (1) to (9). In particular, by calculating the sum of the twosignals and the integral with respect to time of the difference betweenthe two signals, it is possible to compute the down-going sourcewavefield using equation (9). Thus, the present invention enables theeffects of the up-going source wavefield to be removed from theprocessed seismic data. The effect of source-side ghost reflections andreverberations is thus eliminated, or at least significantly reduced.

Results obtained using a seismic source according to the presentinvention and the de-ghosting method of the present invention areillustrated in FIGS. 5-8. These figures relate to a survey carried outusing a source having two emitter arrays, each array having two marinevibrator arrays as the seismic emitters. The source was towed with thearrays at depths of 4 m and 10 m respectively, with a 25 m in linedisplacement (by “in-line displacement” is meant displacement along thetowing direction) between the two arrays. The average water depth was 52m. An ocean bottom cable (OBC) dual sensor cable, 10 km in length,disposed on the sea bed was used as the receiver. The two arrays ofmarine vibrators were fired in a flip-flop mode as described above.

The parameters of the survey arrangement are as follows:

Number of receiver stations: 204

Receiver interval: 25 m

Receiver depth: 52 m

Sweep bandwidth: 5-90 Hz

Fold: 90

The data recorded in the OBC sensors as a result of firing the emitterarray at a depth of 10 m is shown in FIG. 5. This shows the data afterpreliminary processing operations. The emitter array at a depth of 4 mgenerated another record (not shown) at the same x, y location.

FIG. 6 illustrates the data of FIG. 5 after processing, using equation(9) and the data recorded using the emitter array at a depth of 4 m, toremove the up-going wavefield. That is, FIG. 6 shows the data of FIG. 5after de-ghosting to remove the effect of source-side ghost events andreverberations.

FIGS. 7 and 8 show the average amplitude spectra for the seismic data ofFIGS. 5 and 6 respectively. It will be seen that the resolution and thesignal-to-noise ratio have both been improved by de-ghosting process.

In the preferred embodiment described above, the seismic source consistsof two arrays each containing two marine vibrator units. The presentinvention is not, however, limited to this precise arrangement. Forexample, each of the source arrays could contain more than two emittersof seismic energy. Moreover the de-ghosting method of the presentinvention could in principle be applied if seismic data acquired using asingle seismic emitter at one depth and seismic data acquired using anemitter having identical emission characteristics at a different depth(but at the same x- and y-co-ordinates) is available.

In the embodiment shown in FIG. 4, each receiver array is an in-lineemitter array—that is, the emitters of each array are arranged along theaxis of the array. The axis of each array is coincident with the towingdirection when the source is in use. The invention is not, however,limited to use with in-line emitter arrays.

Furthermore, the seismic source of the invention is not limited to asource that contains marine vibrator units. The source could alsoconsist of arrays of other emitters of seismic energy such as, forexample, air guns.

1. A marine seismic source comprising: a first array of N emitters ofseismic energy, where N is an integer greater than one; and a secondarray of N emitters of seismic energy, wherein, in use, the first arrayis disposed at a first depth and the second array is disposed at asecond depth greater than the first depth, the j^(th) emitter of thefirst array (j=1, 2 . . . N) is displaced by a non-zero horizontaldistance d_(H) from the j^(th) emitter of the second array along a firstdirection, and the j^(th) emitter of the first array and the j^(th)emitter of the second array both lie in a common vertical plane parallelto the first direction, wherein the horizontal displacement d_(H)between the j^(th) emitter of the first array and the j^(th) emitter ofthe second array is substantially equal to a shot point interval of asurveying arrangement.
 2. A marine seismic source as claimed in claim 1,wherein the N emitters of the first array are arranged along the axis ofthe first array and the N emitters of the second array are arrangedalong the axis of the second array.
 3. A marine seismic source asclaimed in claim 2, wherein, in use, the first and second arrays aredisposed such that their axes lie substantially in a common verticalplane.
 4. A seismic source as claimed in claim 2 wherein, in use, thefirst and second arrays are disposed such that the axis of the firstarray and the axis of the second array are each substantiallyhorizontal.
 5. A seismic source as claimed in claim 1, wherein each ofthe first and second arrays of emitters of seismic energy comprises Nairguns.
 6. A seismic source as claimed in claim 1, wherein each of thefirst and second arrays emitters of emitters of seismic energy comprisesN marine vibrator units.
 7. A marine seismic source comprising: a firstarray of N emitters of seismic energy, where N is an integer greaterthan one; and a second array of N emitters of seismic energy, wherein,in use, the first array is disposed at a first depth and the secondarray is disposed at a second depth greater than the first depth, thej^(th) emitter of the first array (j=1, 2 . . . N) is displaced by anon-zero horizontal distance d_(H) from the j^(th) emitter of the secondarray along a first direction, and the j^(th) emitter of the first arrayand the j^(th) emitter of the second array both lie in a common verticalplane parallel to the first direction, wherein the first and seconddepths are chosen such that the time taken for seismic energy to travelfrom the first depth to the second depth is greater than twice thereciprocal of the maximum frequency emitted, in use, by the seismicsources.
 8. A marine seismic surveying arrangement, comprising: a marineseismic source comprising: a first array of N emitters of seismicenergy, where N is an integer greater than one; and a second array of Nemitters of seismic energy, wherein, in use, the first array is disposedat a first depth and the second array is disposed at a second depthgreater than the first depth, the j^(th) emitter of the first array(j=1, 2 . . . N) is displaced by a non-zero horizontal distance d_(H)from the j^(th) emitter of the second array along a first direction, andthe j^(th) emitter of the first array and the j^(th) emitter of thesecond array both lie in a common vertical plane parallel to the firstdirection, wherein the horizontal displacement d_(H) between the j^(th)emitter of the first array and the j^(th) emitter of the second array issubstantially equal to a shot point interval of the surveyingarrangement; means for moving the seismic source; and an array of one ormore seismic receivers.
 9. A marine seismic surveying arrangement asclaimed in claim 8 and further comprising control means for firing aselected one of the first and second arrays of emitters of seismicenergy.
 10. A marine seismic surveying arrangement as claimed in claim8, wherein the shot point interval of the surveying arrangement isapproximately 25 m.
 11. A method of operating a marine seismic sourcehaving a first array of N emitters of seismic energy, where N is aninteger greater than one; and a second array of N emitters of seismicenergy, wherein, in use, the first array is disposed at a first depthand the second array is disposed at a second depth greater than thefirst depth, the j^(th) emitter of the first array (j=1, 2 . . . N) isdisplaced by a non-zero horizontal distance d_(H) from the j^(th)emitter of the second array along a first direction, and the j^(th)emitter of the first array and the j^(th) emitter of the second arrayboth lie in a common vertical plane parallel to the first direction themethod comprising the steps of: a) moving the seismic source at a speedv along the first direction; b) firing one of the first and secondarrays of emitters of seismic energy; and c) firing the other of thefirst and second arrays of emitters of seismic energy at a time d_(H)/vafter step (b).
 12. A method as claimed in claim 11 wherein step (b)comprises firing the first array.
 13. A method of processing marineseismic data comprising the steps of: (a) disposing a first emitter ofseismic energy and a second emitter of seismic energy such that thesecond emitter is displaced from the first emitter by a non-zerohorizontal distance along a first direction; (b) firing the firstemitter of seismic energy at a point in a fluid medium having components(x₁, y₁, z₁), and detecting the resultant first seismic data at areceiver array; (c) firing the second emitter of seismic energy at apoint in the fluid medium having components (x₁, y₁, z₂), where z₁≠z₂,and detecting the resultant second seismic data at the receiver array;and (d) using one of the first and second seismic data to reduce theeffects of source-side reflection and or scattering at the sea surfaceon the other of the first and second seismic data.
 14. A method asclaimed in claim 13 wherein step (d) comprises calculatingd(t)=(Sum-Intdif/dt)/4 where Sum is the sum of the first and secondseismic data, Intdif is the integral with respect to time of thedifference between the first and second seismic data; and 2 dt is thetime for seismic energy to travel from the point (x₁, y₁, z₁) to thepoint (x₁, y₁, z₂).
 15. A method as claimed in claim 13, wherein thefirst and second emitters of seismic energy lie in a vertical planeparallel to the first direction.